EX-99.1

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Achieved robust production results from 11 new wells drilled on the western side of our Viking play, reaching an average daily peak rate per well of 293 boe/d for the program

CALGARY, August 2, 2023 - OBSIDIAN ENERGY LTD. (TSX / NYSE American – OBE) (“Obsidian Energy”, the “Company”, “we”, “us” or “our”) is pleased to report solid operating and financial results for the second quarter of 2023.

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We adhere to generally accepted accounting principles (“GAAP”); however, we also employ certain non-GAAP measures to analyze financial performance, financial position, and cash flow, including funds flow from operations (“FFO”), net debt, netback and net operating costs. Additionally, other financial measures are also used to analyze performance. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income and cash flow from operating activities, as indicators of our performance.

Detailed information can be found in Obsidian Energy's unaudited interim consolidated financial statements and management's discussion and analysis ("MD&A") as at and for the three and six-month periods ended June 30, 2023 on our website at www.obsidianenergy.com, which will also be filed on SEDAR and EDGAR in due course.

Our first half 2023 drilling program was completed across our Peace River, Willesden Green, Pembina and Viking areas with all development wells on production by the end of the second quarter. Second quarter 2023 production averaged 31,042 boe/d and was impacted by approximately 2,100 boe/d of temporary production shut-ins in Peace River and Pembina because of the Alberta wildfires. Combined with significantly lower commodity prices, cash flow, FFO and net income decreased compared to the second quarter of 2022.

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Solid Funds Flow – FFO was $87.4 million ($1.07 per basic share) for the second quarter of 2023 compared to $157.0 million ($1.91 per basic share) for the same period in 2022. Lower WTI prices of approximately US$35/bbl primarily drove the decrease, partially offset by realized hedging gains and improvements in heavy oil differentials in 2023. In addition, Alberta wildfires temporarily impacted our Peace River and Pembina operations in the second quarter, resulting in a production decrease of 2,100 boe per day and a corresponding FFO reduction of approximately $6.0 million for the period.

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Enhanced Liquidity – We successfully completed our objective of enhancing our liquidity through a $40.0 million increase to our syndicated credit facility, providing us more flexibility for our return of capital strategy. The amount available under our syndicated credit facility increased to $240.0 million from $200.0 million, with the revolving period and maturity dates remaining at May 31, 2024, and May 31, 2025, respectively. At the same time, our net debt decreased to $324.3 million at June 30, 2023, from $343.0 million at June 30, 2022.

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Commenced Share Buyback Program – In the second quarter of 2023, a total of 1,321,136 shares were repurchased and cancelled under the Company’s normal course issuer bid (“NCIB”) for proceeds of $10.5 million ($7.97 per share). Subsequent to June 30, 2023, we continued to execute our share buyback program, resulting in a total of 2,206,135 shares repurchased and cancelled for proceeds of approximately $18.2 million ($8.27 per share) to date.

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Repurchased Senior Unsecured Notes – During the second quarter of 2023, the Company repurchased $3.6 million principal amount of our senior unsecured notes for cancellation on the open market at an average price of $985.00 per $1,000.00 principal amount (initially issued at a price of $980.00 per $1,000.00 principal amount). Subsequent to June 30, 2023, an additional $0.5 million principal amount of senior unsecured notes were repurchased for cancellation at an average price of $990.00 per $1,000.00 principal amount, resulting in a total of $123.5 million of senior unsecured notes currently outstanding.

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Managed Net Operating Costs – Net operating costs were higher at $15.06 per boe in the second quarter of 2023 compared to $14.02 per boe in the second quarter of 2022. The increase was mainly due to higher power costs, lower production levels compared to the second quarter of 2022 due to the Alberta wildfires, and general inflationary pressures experienced across the industry.

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Higher G&A Costs – General and administrative (“G&A”) costs were $1.85 per boe in the second quarter of 2023 compared to $1.64 per boe in the second quarter of 2022. The continued build-out of our Peace River development team combined with the production impact of the Alberta wildfires increased G&A costs on a per boe basis; we expect G&A costs to decrease to more normalized levels for the remainder of 2023.

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Positive Net Income – Despite the impact of lower commodity prices, solid netbacks contributed to $18.4 million ($0.22 per basic share) of net income for the second quarter of 2023 compared to $113.9 million in the same period in 2022 ($1.39 per basic share).

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Completed First Half Program – Second quarter capital expenditures focused on the completion and tie-in of new wells and were $39.5 million (2022 – $40.3 million) with decommissioning expenditures of $4.9 million (2022 – $3.8 million). In the first half of 2023, 29 (28.8 net) operated wells were drilled (including four oilsands exploration wells) and 33 (32.6 net) wells were brought on production.

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Assessed Peace River Potential – Completed analysis of the well cores gathered from our four (4.0 net) oilsands exploration (“OSE”) wells along with the results of the wells drilled at Walrus in the first quarter. This data provided valuable information that was used in the development of our second half Peace River capital program.

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Achieved Robust Viking Well Results – All 11 (11.0 net) wells were completed and placed on production on the western side of our Viking play, resulting strong initial production (“IP”) rates and an average daily peak rate per well of 293 boe/d for the program.

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Solid Cardium Returns – Completed the first half Cardium development program in Willesden Green and Pembina with strong results, while beginning a major facility debottlenecking project to increase production.

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Safely Managed Response to Alberta Wildfires – Responded to threats from Alberta wildfires in central and northern Alberta, managing operations and protecting the health and safety of our employees and their families in and around our impacted operational areas.

Our 2023 guidance is being revised in response to the impact of Alberta wildfires on our production (~525 boe/d annualized) and expenses in the second quarter, the timing of onstream production with deferral of our Willesden Green debottlenecking project from late July to early November to take advantage of higher, hedged winter gas pricing (~200 boe/d annualized), and the shut-in of a third-party facility affecting nine of our Pembina wells (~120 boe/d annualized). We are evaluating options to bring the Pembina wells back on production. With commodity prices expected to continue at lower levels than originally anticipated in early 2023, we have updated our commodity price assumptions for the year to account for realized price to date and our August 1 to December 31 pricing assumptions of WTI US$75.00/bbl and AECO $2.50/GJ.

Our first half program provided useful information for our Peace River area, which was used to optimize our second half 2023 program and will form the basis of our multi-year Peace River development plan. Our 2023 capital expenditures have been reduced slightly with total well count of 46 (45.5 net) wells under the revised 2023 guidance compared to the previous guidance of 49 (48.2 net) wells, including the four OSE wells. Our lower commodity price forecast combined with lower production (primarily due to the wildfire impact) reduces our funds flow from operations projection.

We expect to continue to generate strong free cash flow in the remainder of 2023 (including after cash used for our share buyback program) and will remain flexible to commodity prices, adjusting our plans accordingly to continue to create value for our stakeholders. Our revised full year 2023 guidance is presented below.

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Approximate mid-point of revised guidance range: 12,400 bbl/d light oil, 6,100 bbl/d heavy oil, 2,500 bbl/d NGLs and 65.3 mmcf/d natural gas. Average production volumes include a minimal amount of forecasted production associated with exploratory capital expenditures.

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Pricing assumptions outlined in table are forecasted for August 1, 2023, to December 31, 2023. Full year pricing assumptions, including actuals realized thus far, result in WTI US$74.90/bbl, AECO $2.91/mcf and WCS differentials of US$17.15/bbl.

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Guidance FFO and free cash flow (“FCF“) include risk management (hedging) adjustments up to August 1, 2023, and includes approximately $6 million of estimated charges for full year 2023 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts which are based on a share price of $9.00 per share. FFO per share is based on 80.3 million shares outstanding as of August 1, 2023, for revised 2023E guidance, and 82.4 million shares outstanding as of January 27, 2023, for 2023E original guidance.

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Net debt figures estimated as at December 31, 2023, and includes the impact of approximately $18.2 million of share purchases under the NCIB to August 1, 2023.Due to changes in the timing of our capital program, our expected working capital deficiency at December 31, 2023, increased by $15.0 million in our 2023E revised guidance.

With most of our drilling activity for the first half development program completed in the first quarter, the second quarter focused on the completion and tie-in of new wells, planned facility turnaround maintenance, assessing data from exploratory/appraisal wells and managing operations safely in and around our operating areas and local communities due to the Alberta wildfires.

In May, a state of emergency was declared for areas in central and northern Alberta due to uncontrolled wildfires with numerous mandatory evacuation orders impacting parts of the Grande Prairie, Kaybob and Peace River regions. Some of Obsidian Energy’s operated and non-operated production was temporarily shut-in during the quarter due to wildfires, evacuation orders and third-party constraints in Peace River and Pembina. There was no significant damage to our assets due to the wildfires and all production was restored in the quarter as access to well pads permitted and power was regained to certain sites. In total, the impact of the wildfires resulted in a production decrease of approximately 2,100 boe per day with a corresponding FFO reduction of approximately $6.0 million for the period.

We are pleased with the results of our first half development and exploration/appraisal program which added production across our Peace River, Willesden Green and Viking areas. During the second quarter,

12 (12.0 net) wells were placed on production from wells drilled earlier in the year. The table below provides our wells drilled and on production by area for the first half of 2023:

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Rig released well totals do not include 11 wells (10.7 net) rig released in 2022 and put on production in 2023, or the eight (2.4 net) non-operated development wells participated in during the first half, one of which was a water injection well.

Our updated 2023 development and exploration/appraisal program is outlined below for wells rig released during the year:

We are pleased with the results of our first half program at Peace River, which provided the first step in unlocking the additional substantial potential across our acreage and established a new development area at Walrus. During the quarter, our Peace River team analyzed the encouraging results from our first half exploration/appraisal drilling program, including the four vertical OSE wells, the Dawson 12-33 Pad well (1.0 net) and data from two other vertical peer wells drilled in the area. Placed strategically across our Peace River acreage, these wells further assessed the development potential of our extensive land base in multiple formations and was used to optimize our second half 2023 program. The data is also key to the development of our multi-year Peace River development plan and to improve future well design. We expect

to rollout a multi-year development and appraisal plan for the Bluesky and Clearwater formations in Peace River in September of 2023.

Peace River operations and production were impacted during the second quarter due to uncontrollable Alberta wildfires. To address this threat, Obsidian Energy temporarily shut-in the Peace River area fields at Harmon-Valley South (“HVS”), Seal, Walrus and Nampa periodically during the second quarter. Production was later restored but resulted in a production decrease of approximately 900 boe/d for the period.

With the completion of the first half 2023 Bluesky development program, we had seven (7.0 net) wells on production by the end of June after adding a second well to the 4-32 Pad, which offset the strong results from the three wells drilled at the HVS 6-31 Pad. Additional 30-day IP rates for the first half 2023 wells were as follows:

During the first half of 2023, the potential of our Walrus acreage was effectively delineated for future large-scale development by the drilling of two (2.0 net) exploration/appraisal wells. Located to the east of our successful HVS development field, the wells exceeded production expectations and provided key data on the Bluesky formation.

During the second quarter, Obsidian Energy focused on planned facility turnaround maintenance and prebuilt infrastructure, primarily well pads and access roads, needed for second half drilling to accelerate the addition of new well production.

In the second half of 2023, we currently plan to drill five (5.0 net) development wells targeting the Bluesky formation. Three (3.0 net) wells follow-up on the success of the Walrus 13-19 Pad exploration/appraisal well drilled during the first quarter that achieved peak production rate of 303 bbl/d (100 percent oil) and established a new development area for the Company. One (1.0 net) well at the Walrus 13-19 Pad will also test a deeper Bluesky zone. If successful, the results could add significant future well inventory and further expand our Bluesky play. The remaining two (2.0 net) wells will be drilled from existing pads in HVS and Cadotte where surface facilities are already in place. We began our second half development program drilling the first well at the HVS 4-32 Pad in July.

The core data analyzed from the OSE wells help to further delineate our land position in Peace River, providing detailed subsurface data for both Bluesky and Clearwater formations. Encouraged by these results, Obsidian Energy plans to drill three (3.0 net) exploration/appraisal wells targeting the Clearwater formation in the Dawson area. We believe there is strong potential for future development in this area.

Obsidian Energy completed our first half development program at Willesden Green with all wells online, resulting in solid production additions to our core field. The final two (2.0 net) first half wells in the program at the 8-36 Crimson Pad exhibited strong results with an average 30-day IP rate of 310 boe/d (40 percent oil) per well.

Following spring break-up in the second quarter, Obsidian Energy began a major debottlenecking project in the East Crimson part of our Willesden Green area to both lower field pressures and expand facility capacity. In addition to increasing base production and reserves, this initiative will provide opportunities to accelerate new development locations. We anticipate that the project will be completed during the fourth quarter of 2023.

In the second half of 2023, we plan to drill seven (6.7 net) wells targeting the Cardium formation at Willesden Green. Three (2.7 net) wells are expected on production by the end of 2023 with the remainder in early 2024.

During the second quarter of 2023, Obsidian Energy focused on planned facility turnaround maintenance and responding to the ongoing threat of the Alberta wildfires in the Pembina area. We temporarily shut-in approximately 11,100 boe/d of light oil weighted production in Pembina due to the wildfires, bringing it back on production by the end of the quarter. In total, the impact of the wildfires resulted in a production decrease of approximately 1,200 boe/d for the period.

We plan to drill two (2.0 net) wells in Pembina in the fourth quarter of 2023 as part of our second half development program.

Following up on the success of the 2022 step-out well on the western side of the play, we drilled and completed 11 (11.0 net) wells in our first half 2023 program by the end of April. All wells were on production in early May, showing robust average daily peak rate per well of 293 boe/d for the program, and daily cumulative rate of over 2,000 boe/d on multiple days.

The initial three (3.0 net) wells brought on production at the 4-22 Pad averaged a 30-day IP rate of 190 boe/d (87 percent light oil) per well. The four well 2-21 Pad and four well 13-16 Pad had average 30-day IP rates of 133 boe/d (86% oil) per well and 190 boe/d (75% oil) per well, respectively. Additionally, during the second quarter Obsidian Energy commissioned the new 13-16 battery in the Viking area to allow for continued growth in the expanded and delineated western region of the play.

Earlier in 2023 the Company established AECO positions across 2023 and into early 2024 given our concerns on natural gas storage levels. With the recent strength in WTI prices and narrowing of WCS differentials, we put in place hedges for these commodities. In addition, we have begun to hedge power prices to help protect against their impact on net operating costs. Currently, the following contracts are in place on a weighted average basis:

As part of the terms of our 11.95 percent July 2027 senior unsecured notes, we are required to provide a repurchase offer (the “Offer”) on a semi-annual basis at a 103 percent of the principal amount to noteholders based on our FCF. The Offer is subject to the Company’s projected leverage and liquidity of our syndicated credit facility, which is required to be at least $60.0 million post the Offer. The FCF available for the Offer based on the results for the first six months of 2023 was $23.5 million. Based on our anticipated available liquidity, we expect to make an Offer of $5.0 million to the noteholders in early August 2023.

FCF offers to noteholders are required until $63.8 million of notes have been repurchased. The purchases made to date of $4.1 million (average price of 98.5 percent) reduce the amount of the Offer, which is now $59.7 million.

For further information on these and other matters, Obsidian Energy will post an updated corporate presentation later today on our website, www.obsidianenergy.com.

Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery. Readers are cautioned that short-term rates should not be relied upon as indicators of future performance of these wells and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.

Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities as indicators of our performance. The Company's unaudited consolidated financial statements and MD&A as at and for the three and six months ended June 30, 2023 are available on the Company's website at www.obsidianenergy.com and under our SEDAR profile at www.sedar.com and EDGAR profile at www.sec.gov. The disclosure under the section "Non-GAAP and Other Financial Measures" in the MD&A is incorporated by reference into this news release.

The following measures are non-GAAP financial measures: FFO; net debt; net operating costs; netback; and FCF. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section "Non-GAAP and Other Financial Measures" in our MD&A for the three and six months ended June 30, 2023, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.

For a reconciliation of FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.

For a reconciliation of net debt to long-term debt, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.

For a reconciliation of net operating costs to operating costs, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.

For a reconciliation of netback to sales price, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.

For a reconciliation of FCF to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.

The following measures are non-GAAP ratios: FFO (basic per share ($/share) and diluted per share ($/share)), which use FFO as a component; net operating costs ($/boe), which uses net operating costs as a component; netback ($/boe), which uses netback as a component; and net debt to FFO, which uses net debt and FFO as components. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section "Non-GAAP and Other Financial Measures" in our MD&A for the three and six months ended June 30, 2023, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.

The following measures are supplementary financial measures: average sales price; cash flow from operating activities (basic per share and diluted per share); and G&A costs ($/boe). See the disclosure under the section "Non-GAAP and Other Financial Measures" in our MD&A for the three and six months ended June 30, 2023, for an explanation of the composition of these measures.

This release contains future-oriented financial information (“FOFI”) and financial outlook information relating to the Company's prospective results of operations, operating costs, expenditures, production, FFO, FCF, net operating costs, and net debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below under "Forward-Looking Statements". The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company's business as of the date hereof and such information may not be appropriate for other purposes.

Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as

“anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: that we will file the unaudited interim consolidated financial statements and MD&A on our website, SEDAR and EDGAR in due course; our updated timing for our onstream production with the deferral of the debottlenecking project; our expectations for development program completion and future development; our pricing assumptions; our expectations of G&A costs for the remainder of 2023; our updated guidance for production, production percentages, capital and decommissioning expenditures, net operating costs, G&A costs, FFO, FCF, net debt and net debt to FFO; our guidance sensitivities; our expectations for development in the Peace River area and when we plan to outline our multi-year development and appraisal plan for the area; our expected timing for the debottlenecking project; our hedges; our expectations in connection with the Offer; and our expectations for an updated corporate presentation.

With respect to forward-looking statements and FOFI contained in this document, the Company has made assumptions regarding, among other things: that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements and FOFI contained herein do not assume the completion of any transaction); the impact of regional and/or global health related events will not have any adverse impact on energy demand and commodity prices in the future; that the Company's operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to any resurgence of the pandemic; global energy policies going forward, including the continued ability of members of OPEC, Russia and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; Obsidian Energy's views with respect to its financial condition and prospects, the stability of general economic and market conditions, currency exchange rates and interest rates, the availability of cash or other financing sources to fund for repurchases of common shares under the NCIB and our ability to comply with applicable terms and conditions under the Company’s debt agreements, the existence of alternative uses for Obsidian Energy's cash resources and compliance with applicable laws and regulations (including Canadian and U.S. securities laws and Canadian corporate law) pertaining to the NCIB; our ability to execute our plans as described herein and in our other disclosure documents and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future net operating costs and G&A costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in production due to low commodity prices or the further deterioration of commodity prices; future exchange rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, wild fires, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our senior unsecured notes on maturity or pursuant to the terms of the underlying agreement; and our ability to add production and reserves through our development and exploitation activities.

Although the Company believes that the expectations reflected in the forward-looking statements and FOFI contained in this document, and the assumptions on which such forward-looking statements and FOFI are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements and FOFI included in this document, as there can be no assurance that the plans, intentions or expectations upon which the

forward-looking statements are based will occur. By their nature, forward-looking statements and FOFI involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements and FOFI contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements and FOFI. These risks and uncertainties include, among other things: our inability to repurchase common shares under the NCIB in the amounts permitted or at all due to a lack of financial resources, the inability to comply with our debt agreements, legal restrictions on share repurchases, competing demands for our financial resources, or other factors; the anticipated benefits of repurchasing our shares under the NCIB do not materialize; Obsidian Energy's future capital requirements; general economic and market conditions; demand for Obsidian Energy's products; and unforeseen legal or regulatory developments and other risk factors detailed from time to time in Obsidian Energy reports filed with the Canadian securities regulatory authorities and the United States Securities and Exchange Commission; the possibility that we change our 2023 budget in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, and the responses of governments and the public to any pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally whether caused by a resurgence of the COVID-19 pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the financial capacity of the Company's contractual counterparties is adversely affected and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our senior unsecured notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our senior unsecured notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or all of our credit facilities and senior unsecured notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior unsecured notes; the possibility that we are unable to complete the Offer with our noteholders; the possibility that we are forced to shut-in production, whether due to commodity prices failing to rise or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company's ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to the ongoing COVID-19 pandemic. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company's Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) which may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) or

Obsidian Energy's website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

Unless otherwise specified, the forward-looking statements and FOFI contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements and FOFI contained in this document are expressly qualified by this cautionary statement.

Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol "OBE".


	Three months ended June 30				Six months ended June 30
	2023		2022		2023		2022
FINANCIAL1 (millions, except per share amounts)
Cash flow from operating activities		67.1		125.0		139.7		208.9
Basic per share ($/share)2		0.82		1.52		1.71		2.55
Diluted per share ($/share)2		0.79		1.48		1.65		2.48
Funds flow from operations3		87.4		157.0		181.7		235.6
Basic per share ($/share)4		1.07		1.91		2.22		2.89
Diluted per share ($/share)4		1.03		1.86		2.14		2.80
Net income		18.4		113.9		48.9		137.7
Basic per share ($/share)		0.22		1.39		0.60		1.69
Diluted per share ($/share)		0.22		1.35		0.58		1.64
Capital expenditures		39.5		40.3		146.6		143.7
Decommissioning expenditures		4.9		3.8		13.6		12.3
Long-term debt		275.2		334.6		275.2		334.6
Net debt3		324.3		343.0		324.3		343.0

OPERATIONS
Daily Production
Light oil (bbl/d)		12,512		12,261		12,660		11,689
Heavy oil (bbl/d)		5,356		6,174		5,797		5,982
NGL (bbl/d)		2,432		2,406		2,554		2,419
Natural gas (mmcf/d)		64		64		66		62
Total production5 (boe/d)		31,042		31,575		32,092		30,497
Average sales price2,6
Light oil ($/bbl)		96.92		139.88		99.23		129.49
Heavy oil ($/bbl)		61.63		106.18		52.71		95.88
NGL ($/bbl)		50.45		82.93		55.10		75.51
Natural gas ($/mcf)		2.56		7.38		3.33		6.21


Netback ($/boe)
Sales price	58.97	96.44	59.95	87.15
Risk management gain (loss)	1.94	(4.66)	1.40	(5.58)
Net sales price	60.91	91.78	61.35	81.57
Royalties	(7.30)	(15.53)	(7.87)	(13.53)
Net operating costs4	(15.06)	(14.02)	(14.81)	(13.98)
Transportation	(3.28)	(3.29)	(3.27)	(3.04)
Netback4 ($/boe)	35.27	58.94	35.40	51.02


		2023E Guidance (Original)	2023E Guidance (Revised)
Production1	boe/d	32,000 – 33,500	31,500 – 32,500
% Oil and NGLs	%	67%	66%
Capital expenditures2	$ millions	260 – 270	255 – 265
Decommissioning expenditures	$ millions	26 – 28	26 – 28
Net operating costs	$/boe	13.50 – 14.40	14.25 – 14.75
General & administrative	$/boe	1.60 – 1.70	1.60 – 1.70

Based on midpoint of above guidance
WTI (Aug 1 – Dec 31)3	US$/bbl	80.00	75.00
WCS differential (Aug 1 – Dec 31)	US$/bbl	22.50	15.00
AECO (Aug 1 – Dec 31)3	$/GJ	3.00	2.50
FFO4	$ millions	~395	~350
FFO4 per basic share	$/share	4.79	4.36
Free Cash Flow4	$ millions	~105	~65
Net debt5	$ millions	~215	~290
Net debt to FFO5	Times	0.5	0.8


Guidance Sensitivity Table1

Variable	Range	Change in 2023 FFO ($ millions)
WTI (US$/bbl)	+/- $1.00/bbl	3.5
MSW light oil differential (US$/bbl)	+/- $1.00/bbl	2.3
WCS heavy oil differential (US$/bbl)	+/- $1.00/bbl	1.2
Change in AECO ($/GJ)	+/- $0.25/GJ	0.5


	H1
Operated Wells	Wells Rig Released1	Wells On Production
Development:
Willesden Green (Cardium)	5 (5.0)	8 (8.0)
Pembina (Cardium / Devonian)	2 (1.8)	4 (3.6)
Peace River (Bluesky)	4 (4.0)	7 (7.0)
Viking	11 (11.0)	11 (11.0)
Total Development	22 (21.8)	30 (29.6)
Exploration/Appraisal:
Peace River (Bluesky)	2 (2.0)	2 (2.0)
Peace River (Clearwater)	1 (1.0)	1 (1.0)
OSE (Peace River)	4 (4.0)	N/A
Total Exploration/Appraisal	7 (7.0)	3 (3.0)
TOTAL	29 (28.8)	33 (32.6)


	Development gross (net) wells			Exploration/Appraisal gross (net) wells			Total 2023
	H1	H2	Total	H1	H2	Total	Program
Willesden Green (Cardium)	5 (5.0)	7 (6.7)	12 (11.7)	-	-	-	12 (11.7)
Pembina (Cardium / Devonian)	2 (1.8)	2 (2.0)	4 (3.8)	-	-	-	4 (3.8)
Peace River (Bluesky)	4 (4.0)	5 (5.0)	9 (9.0)	2 (2.0)	-	2 (2.0)	11 (11.0)
Peace River (Clearwater)	-	-	-	1 (1.0)	3 (3.0)	4 (4.0)	4 (4.0)
Viking	11 (11.0)	-	11 (11.0)	-	-	-	11 (11.0)
TOTAL	22 (21.8)	14 (13.7)	36 (35.5)	3 (3.0)	3 (3.0)	6 (6.0)	42 (41.5)
OSE Wells	-	-	-	4 (4.0)	-	4 (4.0)	4 (4.0)
	22 (21.8)	14 (13.7)	36 (35.5)	7 (7.0)	3 (3.0)	10 (10.0)	46 (45.5)


Type	Remaining Term	Volume (bbl/d)	Swap Price ($/bbl)
WTI Swap	August 2023	4,000 bbl/d		US$78.64
WCS Differential	July 2023 - September 2023	1,000 bbl/d		CAD($21.72)
WCS Differential	October – December 2023	1,500 bbl/d		CAD($21.20)


Type	Term	Volume (mcf/d)		Percentage Hedged1	Swap Price ($/mcf)
AECO Swap	July 2023 – October 2023		49,929	76%	3.48
AECO Swap	November 2023 – March 2024		26,588	41%	3.46


Type	Remaining Term	Volume (MWh/d)	Swap Price ($/MWh)
Power Swap	January - December 2024	24 MWh/d		$96.75


	Three months ended June 30						Six months ended June 30
(millions)	2023			2022			2023			2022
Cash flow from operating activities	$	67.1		$	125.0		$	139.7		$	208.9
Change in non-cash working capital		13.7			26.0			20.3			8.0
Decommissioning expenditures		4.9			3.8			13.6			12.3
Onerous office lease settlements		2.2			2.3			4.5			4.6
Settlement of restricted share units		-			-			4.6			-
Deferred financing costs		(0.6	)		(0.7	)		(1.1	)		(1.4	)
Restructuring charges1		-			-			-			2.5
Transaction costs		-			-			-			0.1
Other expenses1		0.1			0.6			0.1			0.6
FFO		87.4			157.0			181.7			235.6
Capital expenditures		(39.5	)		(40.3	)		(146.6	)		(143.7	)
Decommissioning expenditures		(4.9	)		(3.8	)		(13.6	)		(12.3	)
Free Cash Flow	$	43.0		$	112.9		$	21.5		$	79.6


	As at
	June 30
(millions)	2023				2022
Long-term debt
Syndicated credit facility		$	158.0			$	282.1
Senior unsecured notes			124.0				-
Senior secured notes			-				47.3
PROP Limited recourse loan			-				5.9
Deferred interest			-				0.6
Unamortized discount of senior unsecured notes			(2.1	)			-
Deferred financing costs			(4.7	)			(1.3	)
Total			275.2				334.6

Working capital deficiency
Cash			(0.1	)			(9.2	)
Accounts receivable			(69.6	)			(111.2	)
Prepaid expenses and other			(17.2	)			(15.0	)
Accounts payable and accrued liabilities			136.0				143.8
Total			49.1				8.4

Net debt		$	324.3			$	343.0


Oil		Natural Gas
API	American Petroleum Institute	mcf	thousand cubic feet
bbl	barrel or barrels	mcf/d	Thousand cubic feet per day
bbl/d	barrels per day	mmcf	million cubic feet
boe	barrel of oil equivalent	mmcf/d	Million cubic feet per day
boe/d	barrels of oil equivalent per day	bcf	billion cubic feet
mmbbls	million barrels	NGL	natural gas liquids
mmboe	million barrels of oil equivalent	GJ	gigajoule
MSW	Mixed Sweet Blend	AECO	Alberta benchmark price for natural gas
WTI	West Texas Intermediate
WCS	Western Canadian Select